Rotary drill bits are commonly used to drill in a formation by cutting the soil or rock. Drilling mud is used to control subsurface pressures, lubricate the drill bit, stabilize the well bore, and carry the cuttings to the surface. Mud is pumped from the surface through the hollow drill string, exits through nozzles in the drill bit, and returns to the surface through an annulus between the drill string and the interior wall of the hole.
As the drill bit grinds rocks into drill cuttings, these cuttings become entrained in the mud flow and are carried to the surface. Prior to returning the mud to the recirculating mud system, the solids are separated from the mud. The first step in separating the cuttings from the mud commonly involves circulating the mixture of mud and cuttings over shale shakers. The liquid mud passes through the shaker screens and is recirculated back to the mud tanks from which mud is withdrawn for pumping downhole. The vibratory action of the shakers moves the cuttings down the screen and off the end of the shakers, where they are collected and stored in a tank or pit for further treatment or management. Often two series of shale shakers are used. The first series (primary shakers) use coarse screens to remove only the larger cuttings. The second series (secondary shakers) use fine mesh screens to remove much smaller particles.
Additional mechanical processing is often used in the recirculating mud system to further remove fine solids because these particles tend to interfere with drilling performance. This separation equipment may include one or more of three types: 1) hydrocyclone-type desilters and desanders, 2) mud cleaners (hydrocyclone discharging on a fine screened shaker), and 3) rotary bowl decanting centrifuges. The separated fine solids are typically combined with the larger drill cuttings removed by the shale shakers.
Rate of penetration (ROP) of the drill bit is a major characteristic for wells, and often a critical cost issue for deep wells. Low ROP in the order of 3-5 feet per hour is commonly the result of the high compression strength of formations encountered at the greater depths, and the ineffectiveness of the cutting bit.
Subterranean drill bits can be used in many different applications, such as oil and gas exploration, mining, construction, and geothermal. There are two main types of drill bits. A roller bit uses steel teeth or tungsten carbide inserts mounted with one, two, or three moving rollers. Tricone bits with hardened inserts are used for drilling hard formations at both shallower depths and deeper depths. However, at greater depths it is more difficult to recognize when a tricone bit's bearings have failed, a situation that can occur with greater frequency when greater weight is applied to the bit in a deep well. This can lead to more frequent failures, lost cones, more frequent trips, higher costs and lower overall rates of penetration.
Another type of cutter bit does not use any moving cutting mechanism. Fixed cutter bits with polycrystalline diamond compact (PDC) cutters employ synthetic polycrystalline diamonds bonded to a tungsten-carbide stud or blade. PDC bits typically drill several times faster than tricone bits, particularly in softer formations, and PDC bit life has increased dramatically over the past 20 years. PDC bits nevertheless have their own set of problems in hard formations. For example, “bit whirl” is a problem that occurs when a PDC bit's center of rotation shifts away from its geometric center, producing a non-cylindrical hole. This can result from an unbalanced condition brought on by irregularities in the frictional forces between the rock and the bit. PDC bits are also susceptible to “stick slip” problems where the bit hangs up momentarily, allowing its rotation to briefly stop, and then slips free to rotate at a high speed. While PDC cutters are good at shearing rock, they are susceptible to damage from sharp impacts that lead to problems in hard rocks, resulting in reduced bit life and lower overall rates of penetration. PDC bit designs frequently include features that attempt to address these problems, namely, force balancing, spiraled or asymmetric cutter layouts, gauge rings, and hybrid cutter designs. Nevertheless, PDC bits frequently have significant shortcomings, particularly when drilling in extreme environments.
In a conventional drill bit, the mud flows from one or several nozzles for clearing and cooling the cutters. The mud jet is commonly directed straight from the nozzle to the base of drilling bore (dome). Such flow of the mud causes numerous disadvantages. First, the jet entrains the drill cuttings or solids, and brings them to the bottom of borehole. When drill cuttings go back up to the drill bit cutters, they erode the bits. Another disadvantage it that heat is not appropriately transferred from the bit's cutter to the mud, due to lower speed of the mud flow through the debris slots in the bit. This causes a large heat stress on the cutters thus reducing their rigidity, which in turn reduces the rate of penetration and the operating hours for the drill bit.
U.S. Pat. No. 6,142,248 to Thigpen et al. discloses a method to reduce nozzle erosion using a nozzle which supplies the mud in the laminar flow regime. An enhanced hydraulic design (Mudpick II) plays a key role in the bit performance. The mud stream is directed first to clean the cutters and then it sweeps under a cutter at the point of formation contact for efficient chip removal. The jet path from the nozzle expands and meets the teeth on a roller cone, which commonly are not in the contact with the formation. The jet dissipates and loses hydraulic energy and does not provide the desired efficiency.
The disadvantages of the prior art are overcome by the present invention, and a new rotary drill bit and method of operating a drill bit are hereinafter disclosed.